Method to extract bitumen from oil sands using aromatic amines

ABSTRACT

The present invention relates to an improved bitumen recovery process from oil sands. The oil sands may be surface mined and transported to a treatment area or may be treated directly by means of an in situ process of oil sand deposits that are located too deep for strip mining. Specifically, the present invention involves the step of treating oil sands with an aromatic amine.

FIELD OF THE INVENTION

The present invention relates to the recovery of bitumen from oil sands. More particularly, the present invention is an improved method for bitumen recovery from oil sands through either surface mining or in situ recovery. The improvement is the use of an aromatic amine as an extraction aid in the water and/or steam used in the bitumen recovery process.

BACKGROUND OF THE INVENTION

Deposits of oil sands are found around the world, but most prominently in Canada, Venezuela, and the United States. These oil sands contain significant deposits of heavy oil, typically referred to as bitumen. The bitumen from these oil sands may be extracted and refined into synthetic oil or directly into petroleum products. The difficulty with bitumen lies in that it typically is very viscous, sometimes to the point of being more solid than liquid. Thus, bitumen typically does not flow as less viscous, or lighter, crude oils do.

Because of the viscous nature of bitumen, it cannot be produced from a well drilled into the oil sands as is the case with lighter crude oil. This is so because the bitumen simply does not flow without being first heated, diluted, and/or upgraded. Since normal oil drilling practices are inadequate to produce bitumen, several methods have been developed over several decades to extract and process oil sands to remove the bitumen. For shallow deposits of oil sands, a typical method includes surface extraction, or mining, followed by subsequent treatment of the oil sands to remove the bitumen.

The development of surface extraction processes has occurred most extensively in the Athabasca field of Canada. In these processes, the oil sands are mined, typically through strip or open pit mining with draglines, bucket-wheel excavators, and, more recently, shovel and truck operations. The oil sands are then transported to a facility to process and remove the bitumen from the sands. These processes typically involve a solvent of some type, most often water or steam, although other solvents, such as hydrocarbon solvents, have been used.

After excavation, a hot water extraction process is typically used in the Athabasca field in which the oil sands are mixed with water at temperatures ranging from approximately 35° C. to 75° C., with recent improvements lowering the temperature necessary to the lower portion of the range. An extraction agent, such as sodium hydroxide (NaOH), surfactants, and/or air may be mixed with the oil sands.

Water is added to the oil sands to create an oil sands slurry, to which additives such as NaOH may be added, which is then transported to an extraction plant, typically via a pipeline. Inside a separation vessel, the slurry is agitated and the water and NaOH releases the bitumen from the oil sands. Air bubbles entrained with the water and NaOH attaches to the bitumen, allowing it to float to the top of the slurry mixture and create a froth. The bitumen froth is further treated to remove residual water and fines, which are typically small sand and clay particles. The bitumen is then either stored for further treatment or immediately treated, either chemically or mixed with lighter petroleum products, and transported by pipeline for upgrading into synthetic crude oil. Unfortunately, this method cannot be used for deeper tar sand layers. In situ techniques are necessary to recover deeper oil in well production. It is estimated that around 80 percent of the Alberta tar sands and almost all of the Venezuelan tar sands are too far below the surface to use open pit mining.

In well production, referred to as in situ recovery, Cyclic Steam Stimulation (CSS) is the conventional “huff and puff” in situ method whereby steam is injected into the well at a temperature of 250° C. to 400° C. The steam rises and heats the bitumen, decreasing its viscosity. The well is allowed to sit for days or weeks, and then hot oil mixed with condensed steam is pumped out for a period of weeks or months. The process is then repeated. Unfortunately, the “huff and puff” method requires the site to be shut down for weeks to allow pumpable oil to accumulate. In addition to the high cost to inject steam, the CSS method typically results in 20 to 25 percent recovery of the available oil.

Steam Assisted Gravity Drainage (SAGD) is another in situ method where two horizontal wells are drilled in the tar sands, one at the bottom of the formation and another five meters above it. The wells are drilled in groups off of central pads. These wells may extend for miles in all directions. Steam is injected into the upper well, thereby melting the bitumen which then flows into the lower well. The resulting liquid oil mixed with condensed steam is subsequently pumped to the surface. Typical recovery of the available oil is 40 to 60 percent.

Challenges of in situ methods include low recovery rate and high energy and water requirement. In addition, steam-based methods are not energy-efficient for shallow reservoirs with low maximum operating pressure or reservoirs with thin pay zones.

U.S. Pat. No. 5,264,118 describes a pipeline conditioning process for mined oil sands. The invention related to transport of oil sand with hot water and sodium hydroxide in pipelines of sufficient length. During transportation, bitumen is released from surfaces of oil sand grains and the entrained air helps aeration of liberated bitumen. Caustic is an effective extraction aid but is difficult to control and easy to overdose, which would create stable emulsions that are difficult to separate. High pH due to caustic can result in generating excessive naturally-occurring surfactants from the bitumen surface and possible bitumen emulsification. Moreover, the generated surfactants can absorb at the bitumen/water interface and prevent effective coalescence between bitumen droplets and making it difficult to separate from water. Additionally, the use of a large quantity of caustic not only presents process safety hazards but also contributes to stability of fine clay particles in tailings, the disposal of which is a major environmental problem. The above discussed problems related to the use of caustic can severely compromise the efficiency and quality of bitumen recovery.

Canadian Patent 2004352 discloses use of kerosene and methyl-isobutyl carbinol to address the above mentioned problems related to use of caustic in extracting bitumen, However, the need for large amounts of chemicals increases the operating cost tremendously and makes use of kerosene and methyl-isobutyl carbinol prohibitive.

Canadian Patent 1022098 discloses a method of breaking bitumen-water emulsion created during caustic extraction by adjusting the pH to emulsion to around 7.0 using inorganic salt and carbon dioxide. However, carbon dioxide is not a strong acid and hence not an effective pH reducer. Use of inorganic acids, on the other hand, generates unwanted salt in the process water and can severely limit reuse of the process water.

U.S. Pat. No. 4,357,230 discloses using an amide to extract bituminous materials from shale or sand at a preferred minimum ratio of 1:2 and can be carried out at ambient temperature and pressure. Preferred amide includes di-substituted acid amides with straight or branched chain aliphatic groups attached.

U.S. Pat. No. 5,169,518 discloses ex-situ recovery of bitumen from tar sands where in floatation is improved by the use of alkanolamines Specific examples of useful alkanolamines include mono-, di-, and tri-ethanolamine, isopropanolamines, butanolamine, and hexanolamines and mixtures thereof.

Canadian Patent Application 2,640,448 discloses enhancements in bitumen recovery from oil sands by adding lipids to the ore-water slurry.

U.S. Pat. No. 7,938,183 discloses the use of ammonia and aliphatic amines as low dose (1% or less) for enhancing bitumen recovery in in situ production methods.

U.S. Pat. No. 8,272,442 discloses various classes of additives in combination with the turpentine solvent. These classes include lower aliphatic alcohols, lower alkanes, lower aromatics, aliphatic amines, aromatic amines, carbon bisulfide, vegetable oil and mixtures thereof.

There remains a need for efficient, safe and cost-effective methods to improve the recovery of bitumen from oil sands from surface mining operations and to improve efficiency and productivity of bitumen from in situ production via hot water or steam flooding.

SUMMARY OF THE INVENTION

The present invention is an improved bitumen recovery process comprising the step of treating oil sands with an aromatic amine wherein the treatment is to oil sands recovered by surface mining or in situ production of oil sands in a subterranean reservoir.

In one embodiment of the bitumen recovery process described herein above, aromatic amine is described by the structure:

R¹R²R³N

-   -   wherein R¹ and R² are independently —H, -AL where -AL is an         unsubstituted C₁ to C₂₀, preferably C₁ to C₆ alkyl group, a C₆         to C₁₂ aromatically substituted C₁ to C₂₀, preferably C₁ to C₆         alkyl group, or combination thereof, wherein -AL may contain one         or more of a —COOR⁴ where R⁴ is —H, alkyl, aryl or alkylaryl,         CN, —CHO, —NR⁵R⁶ group where R⁵ and R⁶ are independently —H,         alkyl or aryl, —OH group, —O— group, —S— group, —N— group, —Cl,         —Br, —F, or R¹ and R² may form an unsubstituted or substituted         imine, or R¹ and R² may form a 5 to 7 atom saturated or         unsaturated cyclic moiety wherein there may be one or more         carbon atom, oxygen atom, nitrogen atom, or sulfur atom and     -   R³ is —H or -AR where -AR is an unsubstituted C₁ to C₂₀,         preferably C₁ to C₆ alkyl group, an unsubstituted C₆ to C₁₄         aromatic group, or a C₁ to C₂₀, preferably C₁ to C₆ alkyl group         substituted with one or more C₆ to C₁₄ aromatic group, or a C₆         to C₁₄ aromatic group substituted with one or more C₁ to C₂₀,         preferably C₁ to C₆ alkyl group, or a C₆ to C₁₄ aromatic group         substituted with one or more C₁ to C₂₀, preferably C₁ to C₆         alkyl group and/or one or more C₆ to C₁₄ aromatic group, wherein         -AR may contain one or more of a —COOR⁴ where R⁴ is —H, alkyl,         aryl or alkylaryl, CN, —CHO, —NR⁵R⁶ group where R⁵ and R⁶ are         independently —H, alkyl or aryl, —OH group, —O— group, —S—         group, —N— group, —Cl, —Br, —F, or R¹, R² and R³ may form a 5 to         7 atom saturated or unsaturated cyclic moiety wherein there may         be one or more carbon atom, oxygen atom, nitrogen atom, or         sulfur atom.

Preferably the aromatic amine is 2,4,6-trimethylaniline, N-benzyl-2-phenethylamine, N-butylbenzylamine, dibenzylamine, 2-aminobiphenyl, aminodiphenylmethane, aniline, 2-phenoxyaniline, 9,10-diaminophenanthrene, 1-amino-2-methylnaphthalene, N,N-bis(salicylidene)ethylenediamine, N-phenyl-o-phenylenediamine, 2,4,6-tri-tert-butylaniline, N-phenylglycine, 3,5-di-tert-butylaniline, -1,1′-binaphthyl-2,2′-diamine, 4′-aminobenzo-15-crown 5-ether, α-methylbenzylamine, 4-(dimethylamino)phenylacetic acid, N-benzyl-ethylenediamine, N-methylphenethylamine, 1,2-diphenylethylenediamine, tritylamine, N-phenylethylenediamine, pyridine, toluidine, anisidine, methylaniline, diphenylamine, halogen substitution of aromatic amines, indole, indoline, quinoline, 1-amino-4-alkylaminobenzene, 1,4-diaminobenzene, imidazole, benzimidazole, benzotriazole, pyrrole, 4-dimethylaminopyridine, or mixtures thereof.

In another embodiment of the present invention, the bitumen recovery process by surface mining described herein above comprises the steps of: i) surface mining oil sands, ii) preparing an aqueous slurry of the oil sands, iii) treating the aqueous slurry with the aromatic amine, iv) agitating the treated aqueous slurry, v) transferring the agitated treated aqueous slurry to a separation tank, and vi) separating the bitumen from the aqueous portion, preferably the aromatic amine is present in the aqueous slurry in an amount of from 0.01 to 10 weight percent based on the weight of the oil sands.

In another embodiment of the present invention, the bitumen recovery process by in situ production described herein above comprises the steps of: i) treating a subterranean reservoir of oil sands by injecting hot water and/or steam containing the aromatic amine into a well, and ii) recovering the bitumen from the well, preferably the concentration of the aromatic amine in the steam is in an amount of from 100 ppm to 10 weight percent.

DETAILED DESCRIPTION OF THE EMBODIMENTS

The separation of bitumen and/or heavy oil from oil sands is accomplished by, but not limited to, two methods; surface mining or in situ recovery sometimes referred to as well production. The oil sands may be recovered by surface or strip mining and transported to a treatment area. A good summary can be found in the article “Understanding Water-Based Bitumen Extraction from Athabasca Oil Sands”, J. Masliyah, et al., Canadian Journal of Chemical Engineering, Volume 82, August 2004. The basic steps in bitumen recovery via surface mining include: extraction, froth treatment, tailings treatment, and upgrading. The steps are interrelated; the mining operation affects the extraction and in turn the extraction affects the upgrading operation.

Typically, in commercial bitumen recovery operations, the oil sand is mined in an open-pit mine using trucks and shovels. The mined oil sands are transported to a treatment area. The extraction step includes crushing the oil sand lumps and mixing them with (recycle process) water in mixing boxes, stirred tanks, cyclo-feeders or rotary breakers to form a conditioned oil sands slurry. The conditioned oil sands slurry is introduced to hydrotransport pipelines or to tumblers, where the oil sand lumps are sheared and size reduction takes place. Within the tumblers and/or the hydrotransport pipelines, bitumen is recovered or “released”, or “liberated”, from the sand grains. Chemical additives can be added during the slurry preparation stage; for examples of chemicals known in the art see US2008/0139418, incorporated by reference herein in its entirety. In typical operations, the operating slurry temperature ranges from 35° C. to 75° C., preferably 40° C. to 55° C.

Entrained or introduced air bubbles attaches to bitumen in the tumblers and hydrotransport pipelines creating froth. In the froth treatment step, the aerated bitumen floats and is subsequently skimmed off from the slurry. This is accomplished in large gravity separation vessels, normally referred to as primary separation vessels (PSV), separation cells (Sep Cell) or primary separation cells (PSC). Small amounts of bitumen droplets (usually un-aerated bitumen) remaining in the slurry are further recovered using either induced air flotation in mechanical flotation cells and tailings oil recovery vessels, or cyclo-separators and hydrocyclones. Generally, overall bitumen recovery in commercial operations is about 88 to 95 percent of the original oil in place. The recovered bitumen in the form of froth normally contains 60 percent bitumen, 30 percent water and 10 percent solids.

The bitumen froth recovered as such is then de-aerated, and diluted (mixed) with solvents to provide sufficient density difference between water and bitumen and to reduce the bitumen viscosity. The dilution by a solvent (e.g., naphtha or hexane) facilitates the removal of the solids and water from the bitumen froth using inclined plate settlers, cyclones and/or centrifuges. When a paraffinic diluent (solvent) is used at a sufficiently high diluent to bitumen ratio, partial precipitation of asphaltenes occurs. This leads to the formation of composite aggregates that trap the water and solids in the diluted bitumen froth. In this way gravity separation is greatly enhanced, potentially eliminating the need for cyclones or centrifuges.

In the tailings treatment step, the tailings stream from the extraction plant goes to the tailings pond for solid-liquid separation. The clarified water is recycled from the pond back to the extraction plant. To accelerate tailings handling, gypsum may be added to mature fine tailings to consolidate the fines together with the coarse sand into a non-segregating mixture. This method is referred to as the consolidated (composite) tailing (CT) process. CT is disposed of in a geotechnical manner that enhances its further dewatering and eventual reclamation. Optionally, tailings from the extraction plant are cycloned, with the overflow (fine tailings) being pumped to thickeners and the cyclone underflow (coarse tailings) to the tailings pond. Fine tailings are treated with flocculants, then thickened and pumped to a tailings pond. Further, the use of paste technology (addition of flocculants/polyelectrolytes) or a combination of CT and paste technology may be used for fast water release and recycle of the water in CT to the extraction plant for bitumen recovery from oil sands.

In the final step, the recovered bitumen is upgraded. Upgrading either adds hydrogen or removes carbon in order to achieve a balanced, lighter hydrocarbon that is more valuable and easier to refine. The upgrading process also removes contaminants such as heavy metals, salts, oxygen, nitrogen and sulfur. The upgrading process includes one or more steps such as: distillation wherein various compounds are separated by physical properties, coking, hydro-conversion, solvent deasphalting to improve the hydrogen to carbon ratio, and hydrotreating which removes contaminants such as sulfur.

In one embodiment of the present invention, the improvement to the process of recovering bitumen from oil sands is the addition of an aromatic amine during the slurry preparation stage. The sized material is added to a slurry tank with agitation and combined with an aromatic amine. The aromatic amine may be added to the oil sands slurry neat or as an aqueous solution having a concentration of from 100 ppm to 10 weight percent aromatic amine based on the total weight of the aromatic amine solution. Preferably, the aromatic amine is present in the aqueous oil sands slurry in an amount of from 0.01 to 10 weight percent based on the weight of the oil sands.

In one embodiment of the process of the present invention, the aromatic amine is not added with an organic solvent, for example aromatic organic solvent such as toluene, xylene, benzene, and the like or non-aromatic organic solvent such as alkane hydrocarbons such as C₁ to C₁₂ alkane hydrocarbon, and alkene hydrocarbons such as C₁ to C₁₂ alkylene hydrocarbon. Suitable organic solvents include, but are not limited to, ethanol, propanol, isopropanol, butanol, pentane, heptane, hexane, benzene, xylene, tetraline, carbon bisulfide, soybean oil, palm oil, rapeseed oil, corn oil, sunflower oil, canola oil, and mixtures thereof.

Preferred aromatic amines of the present invention are represented by the following formula:

R¹R²R³N

-   -   wherein R¹ and R² are independently —H, -AL where -AL is an         unsubstituted C₁ to C₂₀, preferably C₁ to C₆ alkyl group, a C₆         to C₁₂ aromatically substituted C₁ to C₂₀, preferably C₁ to C₆         alkyl group, or combination thereof, wherein -AL may contain one         or more of a —COOR⁴ where R⁴ is —H, alkyl, aryl or alkylaryl,         CN, —CHO, —NR⁵R⁶ group where R⁵ and R⁶ are independently —H,         alkyl or aryl, —OH group, —O— group,     -   —S— group, —N— group, —Cl, —Br, —F, or R¹ and R² may form an         unsubstituted or substituted imine, or R¹ and R² may form a 5 to         7 atom saturated or unsaturated cyclic moiety wherein there may         be one or more carbon atom, oxygen atom, nitrogen atom, or         sulfur atom     -   and     -   R³ is —H or -AR where -AR is an unsubstituted C₁ to C₂₀,         preferably C₁ to C₆ alkyl group, an unsubstituted C₆ to C₁₄         aromatic group, or a C₁ to C₂₀, preferably C₁ to C₆ alkyl group         substituted with one or more C₆ to C₁₄ aromatic group, or a C₆         to C₁₄ aromatic group substituted with one or more C₁ to C₂₀,         preferably C₁ to C₆ alkyl group, or a C₆ to C₁₄ aromatic group         substituted with one or more C₁ to C₂₀, preferably C₁ to C₆         alkyl group and/or one or more C₆ to C₁₄ aromatic group, wherein         -AR may contain one or more of a —COOR⁴ where R⁴ is —H, alkyl,         aryl or alkylaryl, CN, —CHO, —NR⁵R⁶ group where R⁵ and R⁶ are         independently —H, alkyl or aryl, —OH group, —O— group, —S—         group, —N— group, —Cl, —Br, —F, or IV, R² and R³ may form a 5 to         7 atom saturated or unsaturated cyclic moiety wherein there may         be one or more carbon atom, oxygen atom, nitrogen atom, or         sulfur atom.

Preferred aromatic amines are 2,4,6-trimethylaniline, N-benzyl-2-phenethylamine, N-butylbenzylamine, dibenzylamine, 2-aminobiphenyl, aminodiphenylmethane, aniline, 2-phenoxyaniline, 9,10-diaminophenanthrene, 1-amino-2-methylnaphthalene, N,N-bis(salicylidene)ethylenediamine, N-phenyl-o-phenylenediamine, 2,4,6-tri-tert-butylaniline, N-phenylglycine, 3,5-di-tert-butylaniline, -1,1′-binaphthyl-2,2′-diamine, 4′-aminobenzo-15-crown 5-ether, α-methylbenzylamine, 4-(dimethylamino)phenylacetic acid, N-benzyl-ethylenediamine, N-methylphenethylamine, 1,2-diphenylethylenediamine, tritylamine, N-phenylethylenediamine, pyridine, toluidine, anisidine, methylaniline, diphenylamine, halogen substitution of aromatic amines, indole, indoline, quinoline, 1-amino-4-alkylaminobenzene, 1,4-diaminobenzene, imidazole, benzimidazole, benzotriazole, pyrrole, 4-dimethylaminopyridine, or mixtures thereof.

The aromatic amine solution/oil sand slurry is typically agitated from 5 minutes to 4 hours, preferably for an hour or less. Preferably, the aromatic amine solution oil sands slurry is heated to equal to or greater than 35° C., more preferably equal to or greater than 40° C., more preferably equal to or greater than 55° C., more preferably equal to or greater than 60° C. Preferably, the aromatic amine solution oil sands slurry is heated to equal to or less than 100° C., more preferably equal to or less than 80° C., and more preferably equal to or less than 75° C.

As outlined herein above, the aromatic amine treated slurry may be transferred to a separation tank, typically comprising a diluted detergent solution, wherein the bitumen and heavy oils are separated from the aqueous portion. The solids and the aqueous portion may be further treated to remove any additional free organic matter.

In another embodiment of the present invention, bitumen is recovered from oil sands through well production wherein the aromatic amine as described herein above can be added to oil sands by means of in situ treatment of the oil sand deposits that are located too deep for strip mining. The most common methods of in situ production recovery are hot water flood, cyclic steam stimulation (CSS), and steam-assisted gravity drainage (SAGD). CSS can utilize both vertical and horizontal wells that alternately inject steam and pump heated bitumen to the surface, forming a cycle of injection, heating, flow and extraction. SAGD utilizes pairs of horizontal wells placed one over the other within the bitumen pay zone. The upper well is used to inject steam, creating a permanent heated chamber within which the heated bitumen flows by gravity to the lower well, which extracts the bitumen. However, new technologies, such as vapor recovery extraction (VAPEX) and cold heavy oil production with sand (CHOPS) are being developed.

The basic steps in the in situ treatment to recover bitumen from oil sands includes: hot water and/or steam injection into a well, recovery of bitumen from the well, and dilution of the recovered bitumen, for example with condensate, for shipping by pipelines.

In accordance with this method, the aromatic amine is used as a hot water and/or steam additive in a bitumen recovery process from a subterranean oil sand reservoir. The mode of hot water and/or steam injection may include one or more of steam drive, steam soak, or cyclic steam injection in a single or multi-well program. Water flooding may be used in addition to one or more of the steam injection methods listed herein above.

Typically, the hot water and/or steam is injected into an oil sands reservoir through an injection well, and wherein formation fluids, comprising reservoir and injection fluids, are produced either through an adjacent production well or by back flowing into the injection well.

In most oil sand reservoirs, a water temperature of at least 150° C. to 180° C. is needed to mobilize the bitumen.

In most oil sand reservoirs, a steam temperature of at least 180° C., which corresponds to a pressure of 150 psi (1.0 MPa), or greater is needed to mobilize the bitumen. Preferably, the aromatic amine-steam injection stream is introduced to the reservoir at a temperature in the range of from 150° C. to 300° C., preferably 180° C. to 260° C. The particular steam temperature and pressure used in the process of the present invention will depend on such specific reservoir characteristics as depth, overburden pressure, pay zone thickness, and bitumen viscosity, and thus will be worked out for each reservoir.

It is preferable to inject the aromatic amine simultaneously with the hot water and/or steam in order to ensure or maximize the amount of aromatic amine actually moving with the steam. In some instances, it may be desirable to precede or follow a steam-aromatic amine injection stream with a steam-only injection stream. In this case, the steam temperature can be raised above 260° C. during the steam-only injection. The term “steam” used herein is meant to include superheated steam, saturated steam, and less than 100 percent quality steam.

For purposes of clarity, the term “less than 100 percent quality steam” refers to steam having a liquid water phase present. Steam quality is defined as the weight percent of dry steam contained in a unit weight of a steam-liquid mixture. “Saturated steam” is used synonymously with “100 percent quality steam”. “Superheated steam” is steam which has been heated above the vapor-liquid equilibrium point. If super heated steam is used, the steam is preferably super heated to between 5 to 50° C. above the vapor-liquid equilibrium temperature, prior to adding the aromatic amine.

The aromatic amine may be added to the hot water and/or steam neat or as a concentrate. If added as a concentrate, it may be added as a 1 to 99 weight percent solution in water.

The aromatic amine is preferably injected intermittently or continuously with the hot water and/or steam, so that the hot water/steam-aromatic amine injection stream reaches the downhole formation through common tubing. The rate of aromatic amine addition is adjusted so as to maintain the preferred aromatic amine concentration of 100 ppm to 10 weight percent in steam. The rate of hot water and/or steam injection for a typical oil sands reservoir might be on the order of enough hot water and/or steam to provide an advance through the formation of from 1 to 3 feet/day.

In one embodiment of the process of the present invention, the bitumen recovery rate over time can be improved by injection of additives in more than one stage, for example: (a) using different additives (or formulations) injected with the hot water and/or steam at different stages, and/or (b) using the same additive (or formulation) injected with hot water and/or steam at different concentrations at different stages. Additives (or formulations) in addition to the aromatic amines of the present invention may be selected based on their performance for enhancing oil drainage in porous media under the range of oil saturation expected in the reservoir in a given stage (e.g., very high oil-saturation at initial well start-up phase and low oil-saturation at declining phase). If a single additive (or formulation) is being used, the oil recovery agent can be injected at lower concentration with hot water and/or steam to help recover oil at high oil saturation, followed by the injection of the same enhanced oil recovery agent at higher concentration as the oil saturation in the formation decreases with time.

In one embodiment of the process of the present invention, the bitumen recovery rate over time can be improved by dividing the total hot water and/or steam composition injection phase into two or more stages, with a different concentration of aromatic amine being selected for each stage.

EXAMPLES Parallel Pressure Reactor (PPR) Testing.

For Examples 1 to 19, approximately, 0.05 g of an aromatic amine, 0.5 g of oil sand, and 5 mL of water is placed into a 12 mL glass vial. The vial is then loosely capped and is then heated for 45 minutes at 120° C. in a convection oven. The oven is then turned off and the sample is allowed to cool down to room temperature. Once cooled, the sample is placed on a white background and a picture is taken. Example 20 is conducted similarly but in the absence of an aromatic amine.

For Examples 21 to 28, the mixtures are prepared as described above but tested at 200° C. and 150 psi. These reactions conditions are representative of the minimum steam conditions necessary to mobilize bitumen in oil-field reservoir using steam-assisted gravity drainage (SAGD) applications. 0.05 g of an aromatic amine along with 0.5 g of oil sand and 5 mL of deionized (DI) water are added into a 15 mL glass insert, which is then transferred and placed in a PPR well and heated for 1 hour. At the end of 1 hour, the sample is cooled and a picture is taken. Example 29 is conducted similarly but in the absence of an aromatic amine.

An additive is deemed to have a positive impact on bitumen liberation from the oil sand if the free oil attached along the glass wall of the vial, above the liquid level, is higher compared to the baseline. The oil liberated is estimated based on color intensity (i.e., higher color intensity would mean higher amount of bitumen liberated) both via visual observation and ImageJ analysis. In ImageJ, the images of the vials are initially converted to 32 bit gray scale and color intensity above the water level is measured and is compared against the baseline (water only). A color intensity of “0” represents complete black and “255” represents complete white. Therefore, the higher the amount of bitumen liberated by an additive compared to the baseline the lower would be the mean intensity ratio.

The mean intensity ratios for Examples 1 to 29 are shown in Table 1:

TABLE 1 Mean Wt Intensity Example Aromatic Amine % Structure Ratio  1 2,4,6- Trimethylaniline 1

0.45  2 N-Benzyl-2- phenethylamine 1

0.51  3 N-Butyl- benzylamine 1

0.58  4 Dibenzylamine 1

0.59  5 2-Aminobiphenyl 1

0.62  6 Aminodiphenyl- methane 1

0.62  7 Aniline 1

0.63  8 2-Phenoxyaniline 1

0.67  9 9,10-Diamino- phenanthrene 0.5

0.73 10 1-Amino-2-methyl- naphthalene 1

0.78 11 N,N-Bis(salicylidene)- ethylenediamine 1

0.82 12 N-Phenyl-o- phenylenediamine 1

0.83 13 2,4,6-Tri-tert- butylaniline 1

0.84 14 N-Phenylglycine 1

0.85 15 3,5-Di-tert-butylaniline 1

0.86 16 1,1′-Binaphthyl-2,2′- diamine 1

0.92 17 4′-Aminobenzo-15- crown 5-ether 1

0.96 18 α-Methylbenzylamine 1

0.98 19 4-(Dimethylamino)- phenylacetic acid 1

0.99 20* Water 1.00 21 2,4,6-Trimethylaniline 1

0.79 22 N-Benzyl- ethylenediamine 1

0.80 23 N-Butylbenzylamine 1

0.81 24 N-Methylphenethyl- amine 1

0.90 25 1,2-Diphenyl- ethylenediamine 1

0.92 26 Tritylamine 1

0.96 27 N-Phenylethylene- diamine 1

0.97 28 2-Phenoxyaniline 1

0.99 29* Water 1.00 *Not an example of the invention 

What is claimed is:
 1. A bitumen recovery process comprising the step of treating oil sands with an aromatic amine wherein the treatment is to oil sands recovered by surface mining or in situ production.
 2. The process of claim 1 wherein the aromatic amine is described by the following structure: R¹R²R³N wherein R¹ and R² are independently —H, -AL where -AL is an unsubstituted C₁ to C₂₀ alkyl group, a C₆ to C₁₂ aromatically substituted C₁ to C₂₀ alkyl group, or combination thereof, wherein -AL may contain one or more of a —COOR⁴ where R⁴ is —H, alkyl, aryl or alkylaryl, CN, —CHO, —NR⁵R⁶ group where R⁵ and R⁶ are independently H, alkyl or aryl, —OH group, —O— group, —S— group, —N— group, —Cl, —Br, —F, or R¹ and R² may form an unsubstituted or substituted imine, or R¹ and R² may form a 5 to 7 atom saturated or unsaturated cyclic moiety wherein there may be one or more carbon atom, oxygen atom, nitrogen atom, or sulfur atom and R³ is —H or -AR where -AR is an unsubstituted C₁ to C₂₀ alkyl group, an unsubstituted C₆ to C₁₄ aromatic group, or a C₁ to C₂₀ alkyl group substituted with one or more C₆ to C₁₄ aromatic group, or a C₆ to C₁₄ aromatic group substituted with one or more C₁ to C₂₀ alkyl group, or a C₆ to C₁₄ aromatic group substituted with one or more C₁ to C₂₀ alkyl group and/or one or more C₆ to C₁₄ aromatic group, wherein -AR may contain one or more of a —COOR⁴ where R⁴ is —H, alkyl, aryl or alkylaryl, CN, —CHO, —NR⁵R⁶ group where R⁵ and R⁶ are independently —H, alkyl or aryl, —OH group, —O— group, —S— group, —N— group, —Cl, —Br, —F, or R¹, R² and R³ may form a 5 to 7 atom saturated or unsaturated cyclic moiety wherein there may be one or more carbon atom, oxygen atom, nitrogen atom, or sulfur atom.
 3. The bitumen recovery process of claim 1 by surface mining comprising the steps of: i) surface mining oil sands, ii) preparing an aqueous slurry of the oil sands, iii) treating the aqueous slurry with the aromatic amine, iv) agitating the treated aqueous slurry, v) transferring the agitated treated aqueous slurry to a separation tank, and vi) separating the bitumen from the aqueous portion.
 4. The bitumen recovery process of claim 3 wherein the aromatic amine is present in the aqueous slurry in an amount of from 0.01 to 10 weight percent based on the weight of the oil sands.
 5. The bitumen recovery process of claim 1 by in situ production comprising the steps of: i) treating a subterranean reservoir of oil sands by injecting hot water and/or steam containing the aromatic amine into a well, and ii) recovering the bitumen from the well.
 6. The bitumen recovery process of claim 5 wherein the concentration of the aromatic amine in the steam is in an amount of from 100 ppm to 10 weight percent.
 7. The process of claim 1 wherein amine is selected from 2,4,6-trimethylaniline, N-benzyl-2-phenethylamine, N-butylbenzylamine, dibenzylamine, 2-aminobiphenyl, aminodiphenylmethane, aniline, 2-phenoxyaniline, 9,10-diaminophenanthrene, 1-amino-2-methylnaphthalene, N,N-bis(salicylidene)ethylenediamine, N-phenyl-o-phenylenediamine, 2,4,6-tri-tert-butylaniline, N-phenylglycine, 3,5-di-tert-butylaniline, -1,1′-binaphthyl-2,2′-diamine, 4′-aminobenzo-15-crown 5-ether, α-methylbenzylamine, 4-(dimethylamino)phenylacetic acid, N-benzyl-ethylenediamine, N-methylphenethylamine, 1,2-diphenylethylenediamine, tritylamine, N-phenylethylenediamine, pyridine, toluidine, anisidine, methylaniline, diphenylamine, halogen substitution of aromatic amines, indole, indoline, quinoline, 1-amino-4-alkylaminobenzene, 1,4-diaminobenzene, imidazole, benzimidazole, benzotriazole, pyrrole, or 4-dimethylaminopyridine. 